Flowline saturation pressure measurement

ABSTRACT

A method for sampling a downhole formation fluid includes pumping formation fluid into the flowline of a downhole sampling tool, measuring a saturation pressure of the formation fluid in the flowline while pumping, and adjusting the pumping rate such that the fluid pressure in the flowline remains within a predetermined threshold above the measured saturation pressure.

CROSS REFERENCE TO RELATED APPLICATIONS

This application is a Divisional Application of U.S. patent applicationSer. No. 15/623,440, filed Jun. 15, 2017 entitled Flowline SaturationPressure Management, now U.S. Pat. No. 10,689,979, which claims thebenefit of, and priority to, U.S. Provisional Patent Application No.62/350,943, filed Jun. 16, 2016 and titled “Flowline Saturation PressureMeasurement.” The foregoing applications are incorporated herein by thisreference in their entirety.

FIELD OF THE INVENTION

Disclosed embodiments relate generally to sampling subterraneanformation fluids and more specifically to a method and apparatus formeasuring a saturation pressure of fluid in the flowline of a downholesampling tool.

BACKGROUND INFORMATION

In order to successfully exploit subterranean hydrocarbon reserves,information about the subsurface formations and formation fluidsintercepted by a wellbore is generally required. This information may beobtained via sampling formation fluids during various drilling andcompletion operations. The fluid may be collected and analyzed, forexample, to ascertain the composition and producibility of hydrocarbonfluid reservoirs.

In order to obtain a reliable characterization of the reservoir fluid,drilling fluid filtrate contamination is desirably minimized, forexample, via pumping fluid overboard until contamination levels reach anacceptably low level. Such a process can be time consuming as itsometimes requires pumping hundreds of liters of fluid overboard.Increasing the flow rate can be problematic as pumping too rapidly mayreduce the flowline pressure below the saturation pressure of the fluidand thereby result in gas bubble formation. Such bubble formation can inturn decrease pumping efficiency and may further degrade opticalspectroscopy measurements used to determine fluid contamination.

There is a need in the art for a method and apparatus for pumpingformation fluid as rapidly as possible without drawing the flowlinepressure below the saturation pressure of the fluid.

SUMMARY

A method for sampling a downhole formation fluid is disclosed. Themethod includes pumping formation fluid into the flowline of a downholesampling tool, measuring a saturation pressure of the formation fluid inthe flowline while pumping, and adjusting the pumping rate such that thefluid pressure in the flowline remains within a predetermined thresholdabove the measured saturation pressure. The saturation pressure may bemeasured in the flowline, for example, by heating formation fluid in theflowline while pumping, estimating a temperature of the fluid in theflowline while heating, evaluating the temperature estimates todetermine a temperature indicative of bubble formation in the flowline,and processing a flowline pressure, a reference temperature, thetemperature indicative of bubble formation, and a formation fluid modelto compute the saturation pressure of the formation fluid at thereference temperature.

A downhole formation fluid sampling tool includes a fluid flowlinedeployed between a fluid inlet probe and a pump (i.e., upstream of thepump) and a bubble sensor deployed in the fluid flowline. The bubblesensor includes a heating element and a temperature sensor deployed on acommon substrate (such as a diamond substrate). The sampling tool mayfurther include a controller configured to implement the above describedmethod.

The disclosed embodiments may provide various technical advantages. Forexample, disclosed embodiments may improve the pumping speed offormation fluid sampling operations while maintaining the flowlinepressure below the saturation pressure of the formation fluid. Thedisclosed embodiments may further enable substantially continuousmeasurements of the saturation pressure in the flowline and thereforeprovide for rapid evaluation and adjustment of fluid sampling pumpingrates.

This summary is provided to introduce a selection of concepts that arefurther described below in the detailed description. This summary is notintended to identify key or essential features of the claimed subjectmatter, nor is it intended to be used as an aid in limiting the scope ofthe claimed subject matter.

BRIEF DESCRIPTION OF THE DRAWINGS

For a more complete understanding of the disclosed subject matter, andadvantages thereof, reference is now made to the following descriptionstaken in conjunction with the accompanying drawings, in which:

FIG. 1 depicts one example of a drilling rig on which disclosed samplingtool and method embodiments may be utilized.

FIG. 2 depicts a downhole sampling tool including a schematic fluid flowcircuit diagram.

FIG. 3 depicts a flow chart of one disclosed method embodiment.

FIG. 4 depicts a plot of formation fluid contamination level versuspumped fluid volume during a sampling operation.

FIG. 5 depicts a portion of a pressure versus temperature phase envelopeof an example crude oil sample.

FIG. 6 plots a portion of the pressure-temperature phase envelope of anexample crude oil sample and further illustrates one disclosed methodembodiment.

FIG. 7 depicts a plot of example estimated saturation pressures versuslaboratory saturation pressure measurements using various types of crudeoils.

FIG. 8 depicts one example embodiment of the bubble sensor shown on FIG.2.

FIG. 9 plots one example of measured temperature sensor responses todifferent fluid types (oil, gas, and water) in a flowline.

FIG. 10 depicts a flow chart of another disclosed method embodiment.

DETAILED DESCRIPTION

FIG. 1 depicts a drilling rig 10 suitable for employing certain downholetool and method embodiments disclosed herein. In the depiction, a rig 10is positioned over (or in the vicinity of) a subterranean oil or gasformation (not shown). The rig may include, for example, a derrick and ahoisting apparatus for lowering and raising various components into andout of the wellbore 40. A downhole sampling tool 100 is deployed in thewellbore 40. The sampling tool 100 may be connected to the surface, forexample, via a wireline cable 50 which may in turn be coupled to awireline truck 55.

During a wireline operation, for example, sampling tool 100 may belowered into the wellbore 40. In a highly deviated borehole, thesampling tool 100 may alternatively or additionally be driven or drawninto the borehole, for example, using a downhole tractor or otherconveyance means. The disclosed embodiments are not limited in thisregard. For example, sampling tool 100 may also be conveyed into theborehole 40 using coiled tubing or drill pipe conveyance methodologies.The sampling tool 100 may alternatively be deployed in a drill stringfor us in a “while-drilling” sampling operation.

The example sampling tool 100 described herein may be used to obtainformation fluid samples from a subterranean formation. The sampling tool100 may include a probe assembly 102 for establishing fluidcommunication between the sampling tool 100 and the subsurfaceformation. During a sampling operation, the probe 102 may be extendedinto contact with the borehole wall 42 (e.g., through a mudcake/filtrate layer). Formation fluid samples may enter the samplingtool 100 through the probe assembly 102 (e.g., via pumping or viaformation pressure).

While the disclosed embodiments are not limited in this regard, theprobe assembly 102 may include a probe mounted in a frame (theindividual probe assembly components are not shown). The frame may beconfigured to extend and retract radially outward and inward withrespect to the sampling tool body. Moreover, the probe may be configuredto extend and retract radially outward and inward with respect to theframe. Such extension and retraction may be initiated via an uphole ordownhole controller. Extension of the frame into contact with theborehole wall 42 may further support the sampling tool in the boreholeas well as position the probe adjacent the borehole wall.

While FIG. 1 depicts a wireline sampling tool 100, it will be understoodthat the disclosed embodiments are not so limited. For example, asstated above, sampling tool 100 may include a drilling tool such as ameasurement while drilling or logging while drilling tool configured fordeployment on a drill string. The disclosed embodiments are expresslynot limited to wireline embodiments.

FIG. 2 further depicts sampling tool 100 including a schematic fluidflow circuit diagram. As described above with respect to FIG. 1, theprobe 102 is depicted as being in contact with the borehole wall 42 forobtaining a formation fluid sample. The probe 102 is in fluidcommunication with a primary flow line 110, which is in furthercommunication with a bubble sensor 200, a fluid analysis module 120, anda pump 130. A sample vessel 140 is also in fluid communication with theprimary flow line 110 and may be configured to receive a formation fluidsample. Sampling tool 100 further includes a fluid outlet line 170configured for discharging unwanted formation fluid into the annulus orinto the subterranean formation.

Fluid analysis module 120 may include substantially any suitable fluidanalysis sensors and/or instrumentation, for example, including chemicalsensors, optical fluid analyzers, optical spectrometers, nuclearmagnetic resonance devices, a conductivity sensor, a temperature sensor,a pressure sensor. More generally, module 120 may include substantiallyany suitable device that yields information relating to the compositionof the formation fluid such as the thermodynamic properties of thefluid, conductivity, density, viscosity, pressure, temperature, andphase composition (e.g., liquid versus gas composition or the gascontent) of the fluid. While not depicted, it will be understood thatfluid analysis sensors may alternatively and/or additionally be deployedon the downstream side of the pump 130, for example, to sense fluidproperty changes that may be induced via pumping.

Substantially any suitable sample vessel 140 may be utilized. The vesselmay optionally include a piston that defines first and second chambers(not shown) within the vessel. As described in more detail below, thebubble sensor 200 may include a diamond substrate having at least oneheating element and at least one temperature sensor deployed thereon.The bubble sensor 200 is preferably deployed on the upstream side of thepump 130 as depicted.

FIG. 3 depicts a flow chart of one disclosed method embodiment 300 forobtaining a formation fluid sample. At 302, formation fluid is drawninto the flowline of a downhole sampling tool (e.g., flowline 110 ofsampling tool 100 depicted on FIGS. 1 and 2). While drawing/pumpingfluid 302, the saturation pressure of the fluid in the flowline may bemeasured at 304 using a bubble sensor (e.g., bubble sensor 200) deployedon the flowline 310. The measurements may optionally be madesubstantially continuously, for example, at a measurement rate in arange from about 1 measurement per minute to about 1 measurement persecond. The pumping rate may be adjusted at 306 in response to thesaturation pressure value(s) measured at 304. The pumping rate ispreferably adjusted such that the pressure in the flowline remainswithin a predetermined threshold above the measured saturation pressure.

As described above in the Background Section of this disclosure, sampledformation fluid is commonly discharged (e.g., via discharge port 170)until contamination levels (e.g., as measured using fluid analysismodule 120) decrease below a predetermined acceptable level. Suchcontamination removal procedures commonly require a large volume offormation fluid to be pumped and discharged, which can be time consumingand expensive. It is therefore generally desirable to pump the formationfluid as rapidly as possible. However, increasing the pumping rate drawsdown the fluid pressure in the flowline upstream of the pump (e.g.,upstream of pump 130 in FIG. 2), which may in turn cause gas bubbles toform if the pressure in the flowline drops below the saturation pressureof the fluid.

The emergence of gas bubbles is generally undesirable for a number ofreasons. For example, formation fluid containing gas bubbles may not berepresentative of the original virgin fluid if the liberated gas is notcaptured with the liquid from which it originated. Moreover, thepresence of gas bubbles may change the compressibility of the fluid andthereby reduce pumping efficiency. The presence of gas bubbles may alsodegrade the reliability of optical spectroscopy measurements used tomonitor fluid contamination due to scattering.

Method 300 is intended to optimize the pumping speed such that a lowcontamination formation fluid sample may be obtained in a timely mannerwithout drawing the flowline pressure below the saturation pressure ofthe fluid.

FIG. 4 depicts a plot of formation fluid contamination level (as avolume fraction) versus pumped volume of fluid during a samplingoperation. Contamination levels are known to decrease approximatelyexponentially with pumped volume independent of the pumping speed(flowrate) and mobility of the fluid. Increased pumping is generallyrequired with increasing invasion (note that contamination levels aresignificantly higher after 54 hours of invasion as compared to 4 hoursof invasion).

FIG. 5 depicts a portion of a pressure versus temperature phase envelopeof an example crude oil sample. As depicted, the saturation pressure(also referred to in the art as the bubble point for an oil or the dewpoint for a retrograde gas) depends on temperature and the contaminationlevel of the fluid. The solid line indicates the phase boundary of thecrude oil having a relatively low contamination level, whereas thedashed line indicates the saturation pressure of crude oil having arelatively high contamination level. For crude oil samples, thesaturation pressure tends to be inversely related to the contaminationlevel (i.e., decreasing with increasing contamination and increasingwith decreasing contamination as depicted).

As described above it is desirable to maintain the flowline pressureabove the saturation pressure to ensure a single phase fluid in theflowline (i.e., with no gaseous components). Initially, the pumpingspeed (the flow rate) may be high since the contamination level isinitially high and thereby allows for a higher drawdown pressure dP₁between the reservoir pressure and the saturation pressure. As pumpingprogresses and the contamination level decreases (e.g., as depicted onFIG. 4), it may be necessary to decrease the pumping speed to reduce thedrawdown pressure (e.g., to dP₂) and avoid bubble formation. During aconventional sampling operation, the saturation pressure of the flowlinefluid is generally unknown and continuously changing as contaminationdecreases. Moreover, as depicted on FIG. 4, the contamination levels mayinitially decrease very rapidly (e.g., exponentially). Real time, rapidsaturation pressure measurements at 304 may enable the pumping rate tobe continually adjusted and optimized at 306 such that a maximum pumpingrate is achieved without causing the flowline pressure to drop below thesaturation pressure.

Measurement of the saturation pressure of the formation fluid at 304 inFIG. 3 is described in more detail with respect to FIG. 6 which plots aportion of the pressure-temperature phase envelope of an example crudeoil sample. The temperature T=T₁ and pressure P of the flowline fluid isdepicted at 312. These parameters may be measured while pumping, forexample, using reference temperature and pressure sensors deployed influid analysis module or elsewhere in the flowline. The saturationpressure P_(b) of the formation fluid may be measured at 304, forexample, by (i) locally heating the flowline fluid (e.g., using theheating element in the bubble sensor 200) until bubbles are formed, (ii)determining a temperature indicative of bubble formation, e.g., thetemperature T₂=T₁+ΔT at which the saturation pressure P′_(b) is equal tothe flowline pressure P (i.e., such that P′_(b)=P at T₂) and (iii)processing P′_(b) and T₂ in combination with a fluid model to computethe unknown saturation pressure P_(b) at temperature T₁.

With continued reference to FIG. 6, local heating of the flowline fluidis depicted at 314. Note that the flowline fluid may be heated at 314until the temperature crosses (or reaches) the phase boundary 316 atwhich point bubble formation may be observed. The temperature T₂=T₁+ΔTat which bubbles form is the temperature at which the phase boundaryintersects the flowline fluid pressure P (i.e., when the saturationpressure P′_(b) is equal to the flowline fluid pressure P) and may bemeasured using the temperature sensor in the bubble sensor. The unknownsaturation pressure P_(b) of the flowline fluid at the flowlinetemperature T₁ may then be computed at 318 via processing P′_(b) and T₂in combination with a fluid model.

Various formation fluid models are known in the art. For example, in oneembodiment, the phase boundary of crude oils may be describedmathematically using an empirical linear regression model includingsecond order terms, for example, as follows:

$\begin{matrix}{{f\left( {T,\left\{ x_{i} \right\}} \right)} = {{a_{T}T} + {b_{T}T^{2}} + {\sum\limits_{i}{a_{i}x_{i}}} + {\sum{\sum\limits_{i \leq j}{b_{ij}x_{i}x_{j}}}}}} & (1)\end{matrix}$

where f (⋅) represents an estimated saturation pressure as a function oftemperature T and fluid compositional inputs {x_(i)} and a_(i) andb_(ij) represent coefficients which are calibrated against a fluidlibrary, where i,j ∈CO₂, C₁, C₂, C₃, C₄, C₅, C₆₊ (with C₁, C₂ . . .representing methane, ethane, etc.).

The difference in saturation pressure dP between the first and secondtemperatures T₁ and T₂ may be derived from Equation 1, for example, asfollows:dP(T ₁ ,T ₂)=f(T ₂ ,{x _(i)})−f(T ₁ ,{x _(i)})=a _(T) dT+b _(T)[2T ₁dT+dT ²]  (2)

where dT=T₂−T₁. An uncertainty δ_(dp) of the estimated saturationpressure difference dP tends to be related to uncertainty in thecoefficients a_(T) and b_(T) and may therefore be quantified using acovariance matrix, for example, as follows:δ_(dP) ² ≈x cov(a _(T) ,b _(T))x ^(T)  (3)

where x=[dT, 2 T₁dT+dT²] and x^(T) represents the transpose of x.

With continued reference to FIGS. 3 and 6, the saturation pressuredecrement dP and its relative uncertainty δ_(dp) may be estimated, forexample, using Equations 2 and 3. Thus the saturation pressure at T₁ maybe estimated, for example, as follows:P _(b)(T ₁)=P−dP±δ _(dP)  (4)

where P_(b) (T₁) represents the saturation pressure at temperature T₁(P_(b) in FIG. 6) and P represents the pressure in the flowline (alsoP′_(b) in FIG. 6).

FIG. 7 depicts a plot of the saturation pressure estimated via Equation4 versus the saturation pressure derived from laboratory measurementsusing various types of crude oils having saturation pressures that rangefrom about 2,000 to about 6700 psi at 75 degrees C. and single-stageflash gas oil ratios ranging from about 160 to 3,000 standard cubic feetper stock tank barrel (scf/stb). In this example, the saturationpressure at T₂ was measured in the laboratory and the saturationpressure at T₁ was estimated using the methodology described above wherea difference between the flowline temperature T₁ and temperature afterheating T₂ was arbitrarily set to 50 degrees (such that dT=50 degrees).Note the excellent fit between the saturation pressure values estimatedusing Equation 4 and those obtained via laboratory measurements. FIG. 7also depicts the uncertainties associated with each estimate computedaccording to Equation 3.

FIG. 8 depicts one example embodiment of the bubble sensor 200 describedabove with respect to FIG. 2. As depicted, the sensor 200 may bedeployed in/on the flowline 110. In the depicted embodiment, the bubblesensor includes first and second temperature sensors 202 and 212 and aheater element 214. Temperature sensor 202 (also referred to as areference temperature sensor) is deployed upstream of temperature sensor212 and heater element 214 and is optional. In the depicted embodiment,temperature sensor 212 and heater element 214 are packaged as a singleelement 210. Suitable sensors and heating elements are disclosed in U.S.Pat. No. 8,616,282, which is incorporated by reference in its entiretyherein.

In a preferred embodiment, sensors 202, 212, and element 214 may bedeployed, for example, on corresponding diamond substrates 205 and 215.The use of a diamond substrate may be advantageous owing to the highthermal conductivity of diamond and its mechanical strength against highpressure and high temperature fluids in the flowline.

During a formation fluid sampling operation, sensor 202 may be used tomeasure the reference temperature of the fluid in the flowline. Heatingand sensing by heater 214 and sensor 212 may be carried outsimultaneously. A suitable heating sequence may make use of AC, DC,and/or pulsed electrical current (the disclosed embodiments are notlimited in this regard). The temperature reading T_(c) at sensor 212will be understood to depend on the local thermal properties of thesystem, including the thermal conductivity and heat capacity of theflowline fluid, and the fluid flow rate. Upon bubble formation (when thetemperature has increased sufficiently to form a bubble in the flowline,for example, as depicted at 225 and as described above with respect toFIG. 6), the heat transfer coefficient between the diamond substrate andthe flowline fluid tends to decrease, thereby resulting in an increasein T_(c). Bubble formation may thus be readily detected via a measuredtemperature profile at sensor 212.

In alternative embodiments, the sampling tool 100 may further (oralternatively) include a thermoelectric cooling element for cooling theformation fluid in the flowline. When sampling dense phase formationfluids, such cooling may induce bubble formation in the flowline (as thefluid cools from the dense phase regime into the two phase regime) andthereby enable the saturation pressure to be determined in a mannersimilar to that described above.

FIG. 9 plots one example of temperature sensor responses to differentfluid types (oil, gas, and water) in a flowline. The temperaturedifference dT=T_(c)−T_(ref) (equivalently dT=T₂−T₁ as shown on FIG. 6where T₂=T_(c) and T₁=T_(ref)) is plotted versus time for an examplesensor arrangement of the type depicted on FIG. 8. The fluid type (oil,gas, or water) is indicated at the top of the plot. In this exampleconstant heat is applied to the flowing fluid. The temperaturedifference dT responds differently depending on the fluid type. Whilenot wishing to be bound by theory, this effect is likely attributable tothe heat transfer coefficients of the fluids which are related to thedifferent thermal conductivity and heat capacity thereof. Note that thetemperature difference dT tends to (i) increase (e.g., at 402) when thefluid is a gas, (ii) remain approximately constant (e.g., at 404) whenthe fluid is oil, and (iii) decrease when the fluid is water (e.g., at406). By evaluating the temperature profile (e.g., a trend of dT withtime) the sensor 200 may be capable of detecting the presence of gasbubbles in the above described methods.

FIG. 10 depicts a flow chart of another disclosed method embodiment 500for obtaining a formation fluid sample. Method 500 is similar to method300 in that formation fluid is drawn/pumped into the flowline of adownhole sampling tool (e.g., flowline 110 of sampling tool 100 depictedon FIGS. 1 and 2) at 502. As described above, the contamination level inthe fluid may be changing continuously while pumping in 502. At 504, thebubble sensor 200 heats the flowline fluid (e.g., by dT) at 504. Thesensor simultaneously measures temperature T_(c) (and optionallyT_(ref)) at 506 to detect bubble formation. If no bubble is detected(e.g., in a predetermined time window), the flow rate may beincrementally increased at 508. If a bubble is detected at 506 (e.g.,via a rapidly increasing dT as described above with respect to FIG. 9),then the saturation pressure P_(b) and its uncertainty may be computedat 509 and 510, for example, as described above with respect toEquations 2-4. The flow rate may then be adjusted (e.g., downward) at512 to avoid bubble formation based on the computed saturation pressureP_(b) (so as to avoid crossing the phase boundary while pumping). Theprocess may continue (as indicated at 514) until a suitable formationfluid sample has been acquired.

Although a flowline saturation pressure measurement method and apparatusand certain advantages thereof have been described in detail, it shouldbe understood that various changes, substitutions and alternations canbe made herein without departing from the spirit and scope of thedisclosure as defined by the appended claims.

What is claimed is:
 1. A method for sampling a downhole formation fluid,the method comprising: (a) pumping formation fluid into a flowline of adownhole sampling tool, wherein the flowline is deployed between a fluidinlet probe and a pump; (b) heating formation fluid in the flowlinewhile pumping in (a); (c) measuring a temperature of the formation fluidin the flowline while heating in (b); (d) evaluating said temperatureestimates in (c) to detect whether or not a gas bubble has formed in theflowline; (e) increasing a pumping rate in (a) when a gas bubble is notdetected in (d); (f) determining a temperature indicative of bubbleformation when a bubble is detected in (d) and processing a flowlinepressure, a reference temperature, the temperature indicative of bubbleformation, and a formation fluid model to compute the saturationpressure of the formation fluid at the reference temperature; and (f)reducing the pumping rate in (a) when the saturation pressure computedin (e) is greater than the flowline pressure.
 2. The method of claim 1,wherein the gas bubble is detected in (d) by evaluating a time basedchange of a difference between said temperature estimates and thereference temperature.
 3. The method of claim 2, wherein the gas bubbleis detected when the difference between said temperature estimates andthe reference temperature increases with time.
 4. A downhole formationfluid sampling tool comprising: a fluid flowline deployed between afluid inlet probe and a pump; and a bubble sensor deployed in the fluidflowline, the bubble sensor including a heating element and atemperature sensor deployed on a common substrate.
 5. The sampling toolof claim 4, further comprising a reference temperature sensor deployedin the fluid flowline upstream of the bubble sensor.
 6. The samplingtool of claim 4, wherein the heating element and the temperature sensorare deployed on a common diamond substrate.
 7. The sampling tool ofclaim 4, further comprising a controller configured to: (i) cause thepump to pump formation fluid through the flowline; (ii) measure asaturation pressure of the formation fluid in the flowline while pumpingin (i); and (iii) adjust a rate of pumping in (i) such that a fluidpressure in the flowline remains within a predetermined threshold abovethe saturation pressure measured computed in (ii).
 8. The sampling toolof claim 4, further comprising a controller configured to: (i) cause thepump to pump formation fluid through the flowline; (ii) cause theheating element to heat the formation fluid in the flowline whilepumping in (i); (iii) cause the temperature sensor to measure atemperature of the formation fluid in the flowline while heating in(ii); (iv) evaluate said temperature measurements in (iii) to determinea temperature indicative of bubble formation in the flowline; (v)process a flowline pressure, a reference temperature, the temperatureindicative of bubble formation, and a formation fluid model to compute asaturation pressure of the formation fluid at the reference temperature;and (vi) adjust a rate of pumping in (i) such that a fluid pressure inthe flowline remains within a predetermined threshold above thesaturation pressure computed in (v).